The invention relates to a method and an apparatus for making measurements of gases and liquids in a core sample. In particular, the invention relates to a method and apparatus for determining simultaneously the saturation of oil, water and a gas in a geological sample.
As the cost of petroleum has increased due in part to the decrease in available domestic supplies of petroleum, it has become economically attractive to extract petroleum from fields which might have been considered to be unproductive a number of years ago. Today, petroleum may be extracted through various tertiary recovery methods or enhanced oil recovery (EOR) methods such as fire flooding, steam flooding, carbon dioxide flooding, by pumping surfactants into geological formations and the like. In addition, solution gas drive, gas cap pressure drive and other methods may be used. It is important to the practice of any of these methods that the characteristics of the geological formation in which the petroleum is located be determined as accurately as possible. In many instances, a selected geological formation which is a potential candidate for tertiary petroleum recovery may contain water, usually in the form of brine; petroleum including crude oil containing mixtures of various light and heavy fractions of hydrocarbons; and gas, which may include natural gas consisting primarily of methane (CH.sub.4).
In a typical secondary or tertiary recovery technique pressure is applied to one or more sites in a region of a potential recoverable field. The pressure forces the petroleum to locations from which it may be pumped out of the ground via wells, etc. In some instances, if the geological formation is highly permeable to a gas such as steam, carbon dioxide, nitrogen or the like, its use may cause failure of the recovery process because the gas will tend to break through or "finger" that is, form a narrow column to the well bore where it is exhausted into the atmosphere without driving the petroleum to the well bore for recovery. This, of course, diminishes if not prevents recovery of the petroleum from the site. If fire flooding techniques are used without having determined the permeability of the geological formation to oil, gas and water, gaseous combustion products of the petroleum also may be vented directly to the atmosphere without forcing the remaining petroleum to move toward the well bore, consuming the petroleum to no good end.
It is therefore important to determine if possible, the relative permeability of the geological formation in which the oil is found. In particular, it is important to determine the relative permeability of the formation for gas, oil and water so that when pressure is applied to the petroleum in the formation, usually by means of a gas, it can be determined whether there is a likelihood that fingering might occur with possible loss of the oil to be recovered.
In the past, laboratory measurements of three-phase relative permeabilities for steady state and unsteady state conditions in core samples have been somewhat inaccurate. In the reported data, in most cases, there was considerable data scatter, which was classified by most researchers as characteristic of three-phase permeability measurements. Most prior art studies employed some type of data smoothing or curve fitting techniques in order to draw meaningful conclusions from the relatively scattered data. Many of those studies indicated that end effects on the cores whose permeability was being measured significantly perturbed the relative permeability measurements. As a result, the regions of the cores within which the three-phase measurements could be made were shown to be quite small. Some researchers have shown that the relative permeability of each of the oil, water and gas phases was a function of its own saturation, whereas other researchers concluded that the permeability of each phase was a function of all three saturations. In most cases, however, relative permeability to water or brine was reported to be a function of brine saturation alone. Oil relative permeability was thought to be a function of the saturations of oil, gas and water. The relative permeability to gas is interpreted either as being solely dependent upon the gas itself or upon the permeability of the oil, water and gas because the observed effects were too small to be considered to be statistically significant when compared to the experimental error. Relative permeability curves could not be described conclusively from published data. Some studies showed relatively large curvatures between 0% and 100% saturation. The curvature in the portions of the graphs where all three phases were indicated to be flowing was rather limited. If the data points were curve-fitted, excluding points outside the three-phase flow region, a straight line also could be fitted to the data within the limits of experimental accuracy. Further, when the saturation of the fluid was found to be lower than the residual saturation, a change in wettability might take place.
It was also found that hysteresis played an important role in unsteady state tests but only had a negligible effect on steady state determinations. The viscosity of the non-wetting phases, such as the oil, had little effect on three-phase relative permeability. However, the viscosity of the wetting phase, in this instance brine, had a substantial effect.
It was found that three-phase relative permeability tests are relatively prone to experimental errors. The most common reported problems, thus, are related to end effects, hysteresis, inaccurate saturation determinations and wettability changes. These problems generally result in considerable scatter of the data points which make the data difficult to interpret using relatively simple statistical techniques, such as manual techniques. Multi-variate interpolation and curve-fitting techniques are required by the data scatter, however, the curves resulting from the use of these techniques usually have the problem of not being unique. Also, the region of the diagrams in which all three phases are found to be flowing is quite limited making it difficult to predict trends. The above problems make it necessary to carefully design methods and apparatus for determining three-phase relative permeability.
In order to define three-phase relative permeability characteristics completely, six separate sets of unsteady state experiments are usually needed to describe all possible displacement histories. However, the time needed for completing a set of six unsteady state runs may still be less than a single steady state test. The possibility of wettability alterations during cleaning and drying and the resaturation of the core being tested and the resulting amounts of time needed to resaturate the core during each of the 6 sets of runs may be relatively large. Moreover, the fluid displacement tests are more prone to core heterogeneities and fluid front instabilities which are difficult to monitor and quantify. Steady state results, however, are less sensitive to hysteresis and tend to approach an average of the drainage and imbibition characteristics of the core being sampled. The steady state technique, therefore, would appear to be more attractive from the standpoint of determining core characteristics.
In U.S. Pat. No. 4,486,714 to Davis, Jr. et al. for Method and Apparatus for Measuring Relative Permeability and Water Saturation of a Core of Earthen Material a two-phase oil and water mixture is injected into an earthen core. Microwave energy is passed through the core while the liquid mixture is flowed through it under pressure. The pressure drop is determined along the length of the core. The relative permeabilities of the oil and water fractions, as well the water saturation of the core, are determined from the flow rate of the liquid mixture, the received microwave energy intensity and the pressure drop across the core.
Similarly U.S. Pat. No. 4,543,821 to Davis, Jr. for Method and Apparatus for Measuring Relative Permeability and Water Saturation of a Core teaches a system for determining the oil and water permeability of a core and its water saturation in a fashion similar to that in Davis, Jr. et al. primarily by means of measuring the amount of microwave energy transmitted through the core which indicates the amount of water in the core absorbing the microwave energy.
Parsons, R. W. "Microwave Attenuation--A New Tool For Monitoring Saturations And Laboratory Flooding Experiments" Society of Petroleum Engineers Journal, August, 1975, discloses a method for determining the amount of water in a core by measuring the absorption of microwave radiation by the electrical dipoles of the water molecules. It may be appreciated that the discussion points that most gases and liquids have negligible loss factors at microwave frequencies, water being an exception.
In another type of system the relative permeabilities of two materials may be determined by means of X-ray absorption measurements, Oak, M. J. and Ehrlich, R., "A New X-ray Absorption Method For Measurement of Three-Phase Relative Permeability", Society of Petroleum Engineers (1985) SPE-14420 discloses a system wherein X-ray absorption is measured for a three-phase system. The absorption is measured at X-ray potentials between 33 kilovolts and 45 kilovolts. It should be noted that the three-phase system consists of water, oil and gas both the water and oil phases having a specific tracer or X-ray absorption media associated therewith. The X-ray absorption equipment specifically uses scintillation measuring techniques to selectively measure X-ray intensities at each of two wavelength bands for which band splitting is provided by an iodine filter. Electric pulses generated by the X-ray photons in the scintillation counter are received by pulse height analyzers or selectors so that X-ray photons belonging to the separate wavelength bands corresponding to the two absorption regions may be distinguished.
U.S. Pat. No. 4,669,299 to Closman for Measuring Relative Permeability to Steam in Cores of Water and Oil Containing Reservoir Formations is directed to an X-ray scanning technique for sealed cores for determining the saturation from the density of tagged oil volumes and the permeability of the core from the densities in combination with measured pressures and temperatures.
Unfortunately, the prior art systems suffer from several defects. Both the Oak, et al. and Closman X-ray systems require that the material which absorbs the X-rays be associated with the water or oil, thus the liquid phases must be tagged in the event that three-phase measurements are to be made for a pair of liquid phases and a gas phase; each of the liquid phases must be tagged with a separate absorber. The use of absorbers, however, changes the relative saturation and permeability of the core because of changes in the surface interactions between the interior surfaces of the core and the tag liquids. Thus, as additional tagging agents are used the measured behavior of the core departs from the in situ behavior of the core exposed only to pure oil, brine and gas. As a result, the X-ray systems which tag both of the liquid phases perturb the saturation and permeability measurements.
The microwave measurements of the type disclosed in Davis, Jr. et al., Davis, Jr., and Parsons do not require the use of a tag medium. Oil and gas, however, have substantially the same absorption for microwave radiation, practically nil. Thus, it is almost impossible, using only microwave determinations, to determine whether the remaining volume of the core sample is primarily oil or gas. While gravimetric methods may be used to determine mass changes as the core is dried or filled with fluid, only relatively small changes occur and if the densities of the two fluids are relatively close, it is impossible to determine how much oil is present in the core sample.
It would be desirable to configure an apparatus for the determination of the saturation water, oil, and gas in a way which utilizes both X-ray and microwave radiation. In so doing, water measurements can be made independent of oil measurements. The microwave system could be utilized to measure water saturation without the need to tag the water while the X-ray system could be utilized to measure tagged oil. Since the oil would be the only liquid tagged with an absorber, changes in the relative saturation and permeability of the core would be minimal. The X-ray absorption by water remains practically nil and the microwave absorption by the oil also remains practically nil. Thus, the microwave and X-ray systems act independent of each other. Moreover, the use of two fluid measurement systems in one apparatus could facilitate the calibration of one system from the other. Unfortunately, the prior art systems have not been able to utilize such a calibration scheme due to difficulties associated with establishing a linear calibration line to relate the X-ray energies to microwave energies or the microwave energies to X-ray energies.
It is also desirable and necessary to make fluid measurements over a broad dynamic range of possible values for saturation and permeability levels. The desire to make three-phase steady state measurements makes this requirement even more crucial and difficult. When three fluid phases coexist in one core sample, naturally saturation levels may swing from practically nil to high saturation levels in a given area of the core sample. This presents a particular problem when measurement devices can only measure accurately over a relatively narrow range of values. The use of lanthanum X-ray targets and iodine tagging in X-ray systems for measuring oil saturations have adequately dealt with this problem and this is taught by the prior art. However, microwave detectors used to measure water levels typically have a limited dynamic measurement range. The ability to circumvent this problem associated with microwave measurements would enable one to accurately measure water saturation levels in a three-phase system. Moreover, measurements on cores with wider diameters would also be facilitated by such a system.
It would be further desirable to simulate actual reservoir conditions by elevating the temperature and pressure of the core sample. This is known to have the effect of causing condensation of heavy hydrocarbon gas or wet gas. Since in situ condensation affects overall three-phase permeabilities, the ability to measure condensation under real temperature and pressure conditions more accurately determines the three-phase permeability characteristics of a core sample.
It is still further desirable to visually monitor fluid characteristics and flow patterns through the core sample. The ability to do so would provide feedback as to whether the measurement system is providing realistic information about core permeabilities.